Process for treating a formation

ABSTRACT

A method of introducing an oil field or gas field production chemical into a hydrocarbon-bearing porous subterranean formation penetrated by a wellbore comprising: injecting a gelling composition comprising an aqueous liquid, an oil field or gas field production chemical, and a gellable polymer through the wellbore into the porous subterranean formation wherein the gellable polymer forms a gel within the pores of the subterranean formation thereby encapsulating the production chemical in the gel; and controllably releasing the production chemical from the gel into a formation fluid.

This application is the U.S. National Phase of International ApplicationPCT/GB2003/003428, filed 6 Aug. 2003, which designated the U.S.PCT/GB2003/003428 claims priority to British Application No. 0219037.9filed 15 Aug. 2002. The entire content of these applications areincorporated herein by reference.

The present invention relates to oil field or gas field productionchemicals, in particular, scale inhibitors and their use.

BACKGROUND OF THE INVENTION

Scale inhibitors are used in production wells to stop scaling in therock formation and/or in the production lines down hole and at thesurface. Scale is a slightly soluble inorganic salt, such as barium orstrontium sulphate, calcium carbonate, calcium sulphate or calciumfluoride. In the production of hydrocarbons from subterranean formationsthe deposition of scale on surfaces and production equipment is a majorproduction problem. Scale build-up decreases permeability of theformation, reduces well productivity and shortens the lifetime ofproduction equipment. In order to clean scaled-up wells and equipment itis necessary to stop the production i.e. by shutting in the well whichis time-consuming and costly.

To minimise scale build-up a solution of a scale inhibitor may beinjected by force into the formation via a production well-bore. Afterinjection the production well is shut-in during which time the scaleinhibitor is absorbed within the formation. After the shut-in period theproduction well is returned on stream and the inhibitor is slowlydesorbed into the fluids in the formation to inhibit scale deposition.The fluids produced therefrom are analysed to determine the scaleinhibitor concentration. When the concentration of inhibitor in thefluids has reduced to a certain level then further treatments will berequired. An aqueous-based scale inhibitor may have a short lifetime ofa few weeks. The continual need for such treatments is therefore costly,not only in terms of production shut down periods but also in the costof the chemical scale inhibitor used.

Other water-soluble or water-dispersible inhibitors used in productionwell environments include corrosion inhibitors, hydrogen sulphidescavengers or hydrate inhibitors. These too may need shut-ins.

According to U.S. Pat. No. 5,547,025, it is well-known to those skilledin the art that gelled or crosslinked water-soluble polymers are usefulin enhanced oil recovery and other oil field operations. In particular,they have been used to alter the permeability of underground formationsin order to enhance the effectiveness of water flooding operations.Generally, polymers along with an appropriate crosslinking system areinjected in an aqueous solution into the formation. The polymers thenpermeate into and gel in the regions of the formation having the highestwater permeability. Specifically, the process of U.S. Pat. No. 5,547,025comprises injecting into a formation a gelling composition whichcomprises a carboxylate-containing polymer, a crosslinking agent and aliquid wherein the gelling composition forms a gel when injected intothe formation.

DETAILED DESCRIPTION OF THE INVENTION

It has now been found that delayed release of an oil field or gas fieldproduction chemical can be achieved by incorporating the productionchemical in a gelling composition which is injected into ahydrocarbon-bearing subterranean formation thereby allowing a decreasein the frequency of squeeze/shut in operations and an increase in theoil/gas production rate.

Thus, according to a first embodiment of the present invention there isprovided a method of introducing an oil field or gas field productionchemical into a hydrocarbon-bearing porous subterranean formationpenetrated by a wellbore comprising:

injecting a gelling composition comprising an aqueous liquid, an oilfield or gas field production chemical, and a gellable polymer throughthe wellbore into the porous subterranean formation wherein the gellablepolymer forms a gel within the pores of the subterranean formationthereby encapsulating the production chemical in the gel; andcontrollably releasing the production chemical from the gel into aformation fluid.

Controlled release of the oil field or gas field production chemical(hereinafter “production chemical”) into the formation fluid occurs upondegrading or breaking of the gel and is advantageous in that it extendsthe lifetime of the production chemical and reduces the number oftreatments required. Consequently production downtime and chemical costsare reduced.

The gelling composition is preferably injected into the near wellboreregion of the well such that the gel is set up and the productionchemical is controllably released therefrom in the near wellbore region.By “near well bore region” is meant a radial distance of less than 100feet, preferably less than 50 feet, more preferably, less than 30 feetfrom the wellbore.

Preferably, the gel is substantially immobile within the pores of theformation.

Without wishing to be bound by any theory, it is believed that the gelmay act as a relative permeability modifier. Thus, hydrocarbon formationfluids may diffuse or percolate through the gel at a faster rate thanaqueous formation fluids.

Suitably, the production chemical is released into an aqueous formationfluid, a hydrocarbon formation fluid or a mixture thereof. Preferably,the aqueous formation fluid is a brine. Preferably, the hydrocarbonformation fluid is selected from the group consisting of crude oil,natural gas and gas field condensate.

Preferably, the production chemical is controllably released from thegel over a period of at least 1 month, more preferably 3 to 12 months.

It is envisaged that the gelling composition may comprise an admixtureof the aqueous liquid, the production chemical and the gellable polymerand it is this admixture which is injected into the subterraneanformation. Suitably, the production chemical may be dissolved, dispersedor suspended in the aqueous liquid of the admixture. Suitably, thegellable polymer is dissolved or dispersed in the aqueous liquid of theadmixture.

Gellable polymers suitable for use in this invention are those which aresoluble or dispersible in an aqueous liquid to increase the viscosity ofthe liquid. Preferred gellable polymers are those which are capable ofcrosslinking with a suitable crosslinking agent via crosslinkablegroups.

Thus, according to a preferred embodiment of the present invention thereis provided a method of treating a hydrocarbon-bearing poroussubterranean formation penetrated by a wellbore comprising:

injecting a gelling composition comprising: (i) an aqueous liquid, (ii)an oil or gas field production chemical, (iii) a gellable polymer havingcrosslinkable groups, and (iv) a crosslinking agent through the wellboreinto said porous subterranean formation wherein a gel is formed withinthe pores of the formation through crosslinking of the crosslinkablegroups of the polymer with the crosslinking agent thereby encapsulatingthe oil or gas field production chemical in the gel; and controllablyreleasing the oil or gas field production chemical from the gel into theformation fluids.

It is envisaged that the gelling composition may comprise an admixtureof the aqueous liquid, the production chemical, the gellable polymer andthe crosslinking agent. Alternatively, the gellable polymer may bedispersed or dissolved in a first aqueous fluid (hereinafter “polymerslug”) and the crosslinking agent may be dissolved in a second aqueousfluid (hereinafter “crosslinking agent slug”). The polymer slug andcrosslinking agent slug are then injected sequentially into theformation with the production chemical dissolved, dispersed or suspendedin the polymer slug and/or the crosslinking agent slug. It is envisagedthat the polymer slug may be injected into the formation before thecrosslinking agent slug or vice versa. Optionally, an aqueous spacer isinjected between the polymer slug and crosslinking agent slug.Optionally, the subterranean formation is pre-flushed with an aqueousfluid prior to injection of the polymer slug and crosslinking slug.Suitably, the production chemical may be dissolved, dispersed orsuspended in one or more of the aqueous pre-flush fluid, the polymerslug, the crosslinking agent slug or aqueous spacer. Optionally, thesubterranean formation is over-flushed with an aqueous fluid. Duringsequential addition, the gelling composition is formed within theformation by either back-producing the gellable polymer over thecrosslinking agent or back-producing the crosslinking agent over thegellable polymer. Where the production chemical is dissolved, dispersedor suspended in the pre-flush fluid it is necessary to back produce thepre-flush fluid over the polymer and crosslinking agent.

Preferably, the gel that is formed within the pores of formation throughcrosslinking of the crosslinkable groups of the gellable polymer withthe crosslinking agent is of a type that is collapsible to allowhydrocarbon flow, as described in International patent applicationnumbers WO 01/49971 and WO 03/033860 which are herein incorporated byreference.

Suitably the oil or gas field production chemical is selected from (i)scale inhibitors, (ii) corrosion inhibitors, (iii) hydrogen sulphidescavengers and (iv) hydrate inhibitors.

Scale inhibitors include water-soluble organic molecules having at least2 carboxylic and/or phosphonic acid and/or sulphonic acid groups e.g.2-30 such groups. Preferred scale inhibitors are oligomers or polymers,or may be monomers with at least one hydroxyl group and/or aminonitrogen atom, especially in hydroxycarboxylic acids or hydroxy oraminophosphonic, or, sulphonic acids. Scale inhibitors are usedprimarily for inhibiting calcium and/or barium scale. Examples of suchcompounds used as scale inhibitors are aliphatic phosphonic acids having2-50 carbons, such as hydroxyethyl diphosphonic acid, and aminoalkylphosphonic acids, e.g. polyaminomethylene phosphonates with 2-10 N atomse.g. each bearing at least one methylene phosphonic acid group; examplesof the latter are ethylenediamine tetra(methylene phosphonate),diethylenetriamine penta(methylene phosphonate) and the triamine- andtetramine-polymethylene phosphonates with 2-4 methylene groups betweeneach N atom, at least 2 of the numbers of methylene groups in eachphosphonate being different (e.g. as described further in publishedEP-A479462, the disclosure of which is herein incorporated byreference). Other scale inhibitors are polycarboxylic acids such asacrylic, maleic, lactic or tartaric acids, and polymeric anioniccompounds such as polyvinyl sulphonic acid and poly(meth)acrylic acids,optionally with at least some phosphonyl or phosphinyl groups as inphosphinyl polyacrylates. The scale inhibitors are suitably at leastpartly in the form of their alkali metal salts e.g. sodium salts.

Examples of corrosion inhibitors are compounds for inhibiting corrosionon steel, especially under anaerobic conditions, and may especially befilm formers capable of being deposited as a film on a metal surfacee.g. a steel surface such as a pipeline wall. Such compounds may benon-quaternised long aliphatic chain hydrocarbyl N-heterocycliccompounds; mono- or di-ethylenically unsaturated aliphatic groups e.g.of 8-24 carbons such as oleyl are preferred. The N-heterocyclic groupcan have 1-3 ring nitrogen atoms with 5-7 ring atoms in each ring;imidazole and imidazoline rings are preferred. The ring may also have anaminoalkyl e.g. 2-aminoethyl or hydroxyalkyl e.g. 2-hydroxyethylsubstituent. Oleyl imidazoline may be used. Where corrosion inhibitorsare released into the formation using the method of the presentinvention, these inhibitors are effective in reducing corrosion of metalsurfaces as they are produced out of the well.

Hydrogen sulphide scavengers include oxidants, such as inorganicperoxides, e.g. sodium peroxide, or chlorine dioxide, or aldehydes e.g.of 1-10 carbons such as formaldehyde or glutaraldehyde or(meth)acrolein.

Hydrate inhibitors include salts of the formula [R¹(R²)XR³]⁺Y⁻, whereineach of R¹, R² and R³ is bonded directly to X, each of R¹ and R², whichmay the same or different is an alkyl group of at least 4 carbons, X isS, NR⁴ or PR⁴, wherein each of R³ and R⁴, which may be the same ordifferent, represents hydrogen or an organic group with the proviso thatat least one of R³ and R⁴ is an organic group of at least 4 carbons andY is an anion. These salts may be used in combination with a corrosioninhibitor and optionally a water soluble polymer of a polarethylenically unsaturated compound. Preferably, the polymer is ahomopolymer or a copolymer of an ethylenically unsaturatedN-heterocyclic carbonyl compound, for example, a homopolymer orcopolymer of N-vinyl-omega caprolactam. Such hydrate inhibitors aredisclosed in EP 0770169 and WO 96/29501 which are herein incorporated byreference.

Suitably, the oil or gas field production chemical (hereinafter“production chemical”) is water-soluble or water-dispersible.Alternatively, particles of the production chemical may be suspended inthe aqueous liquid component of the gelling composition. The particlesize should be sufficiently small to allow the particles to enter aformation. If the particles are too large they will tend to settle outand potentially lead to agglomeration problems. The particle size may be100% less than 10 microns, preferably 100% less than 7 microns andespecially 100% less than 5 microns. Preferably the particle size is notless than 25 nanometres and advantageously not less than 200 nanometres.The average particle size is usually between 1 and 3 microns. Theparticulate production chemical may be of the type described in EP0902859 which is herein incorporated by reference.

The particulate production chemical may be coated with a suitablecoating agent also as described in EP 0902859. The coated particulateproduction chemical may be isolated from its production medium beforedispersion in the gelling composition.

Suitable coating agents include water-soluble polymers or oil-solublepolymers. Preferred water-soluble polymers for coating the particles ofproduction chemical include polyacrylic acids; polymaleic acids;polyacrylamide; polymethacrylate; polyvinylsulphonates; copolymers ofmonomers selected from the group consisting of acrylic acid, maleicacid, acrylamide, methacrylate, 2-acrylamido-2-methylpropane-sulfonicacid, and vinylsulphonate; lignosulphonates; hydroxy methyl cellulose;carboxy methyl cellulose; carboxy methyl ethyl cellulose; hydroxy methylethyl cellulose; hydroxylpropyl methyl cellulose; methyl hydroxy propylcellulose; sodium alginates; polyvinyl pyrolidone; polyvinyl pyrolidoneacrylic acid co-polymers; polyvinyl pyrolidone caprolactam co-polymers;polyvinyl alcohol; polyphosphates, polystyrene-maleinates, poloxamersand poloxamines. Suitably, the poloxamers are linear ABA blockco-polymers having the general structure (EO)_(n)—(PO)_(m)—EO)_(n) wheren and m are integers and EO and PO represents structural units derivedfrom ethylene oxide and propylene oxide respectively. Suitably, thepolaxamines are ABA block co-polymers having a branched structure with acentral ethylene diamine bridge i.e.([(EO)_(n)—(PO)_(m)]₂—N—CH₂—CH₂—N—[(EO)_(n)—(PO)_(m)]₂) where n, m, EOand PO have the same meaning as for the poloxamers. Preferably, thewater-soluble polymer has a molecular weight in the range 1,000-100,000,preferably 5,000 to 30,000, for example, 15,000 to 25,000. Preferredoil-soluble polymers for coating the particles of production chemicalinclude polyethers, polyamine derivatives or carbon backbone polymershaving pendant nitrogen and/or oxygen atoms as described in EP 0902859.

Without wishing to be bound by any theory, the polymer will precipitateonto the particles of production chemical and will at least partiallycoat the particles. Suitably, at least 75%, preferably, at least 90%,more preferably, at least 95% of the surface of the particles is coatedwith the polymer. Preferably, the coating is continuous (100% surfacecoverage). Preferably, the coating has a thickness of less than 30 nm,preferably, less than 20 nm.

The coated production chemical provides for further controlled releaseof the production chemical into the formation fluids and/or the producedfluids.

Gellable polymers suitable for use in this invention include but are notlimited to biopolysaccharides, cellulose ethers andacrylamide-containing polymers. Suitably, the gellable polymers containcrosslinkable groups such as carboxylate, phosphonate or hydroxylgroups. Where the polymer contains carboxylate and/or phosphonate groupsthese groups may be in their acid or salt form. Suitable salts includeammonium, alkali metal or alkaline earth metal salts.

Suitable biopolysaccharides include natural and derivatizedpolysaccharides which are soluble or dispersible in an aqueous liquid toincrease the viscosity of the liquid. Examples of natural gums includearabic gum, ghatti gum, tamarind gum, tagacanth gum, guar gum, locustbean gum, karaya gum, xanthan gum, galactomannan gum and the like.Preferred biopolysaccharides have molecular weights in the range 200,000to 3,000,000. Modified gums such as carboxyalkyl derivatives, forexample, carboxymethyl guar, and hydroxyalkyl derivatives, for example,hydroxyethyl guar, hydroxypropyl guar can also be employed. Doublyderivatized gums such as carboxymethylhydroxyethyl guar,carboxymethylhydroxypropyl guar can also be used.

Modified celluloses and derivatives thereof can also be employed in thepractice of the present invention, for example, cellulose ethers, estersand the like. In general, any of the water-soluble cellulose ethers canbe used. These cellulose ethers include, among others, the variouscarboxyalkyl cellulose ethers, such as carboxyethyl cellulose andcarboxymethyl cellulose; mixed ethers such as carboxyalkylhydroxyalkylcellulose ethers, e.g., carboxymethyl hydroxyethyl cellulose;hydroxyalkyl celluloses such as hydroxyethyl cellulose and hydroxypropylcellulose; alkylhydroxyalkyl celluloses such as methylhydroxypropylcellulose; alkyl celluloses such as methyl cellulose, ethyl celluloseand propyl cellulose; alkylcarboxyalkyl celluloses such asethylcarboxymethyl cellulose; alkylalkyl celluloses such asmethylethylcellulose; hydroxyalkylalkyl celluloses such ashydroxypropylmethyl cellulose; and the like.

Other suitable gellable polymers include the various polyacrylamides andrelated polymers which are partially hydrolysed and which arewater-soluble, such as those disclosed in U.S. Pat. No. 3,749,172 and EP0 604 988 (herein incorporated by reference). Examples of suitablepolymers include the homopolymers and copolymers of acrylamide andmethacrylamide. Also, suitable are water-soluble copolymers resultingfrom the polymerisation of acrylamide and/or methacrylamide with anotherethylenically unsaturated monomer copolymerisable therewith, whereinsufficient acrylamide and/or methacrylamide is present in the monomermixture to impart water-solubility to the resulting copolymer. Theethylenically unsaturated monomer which is copolymerisable with theacrylamide and/or methacrylamide may be selected from the groupconsisting of acrylic acid, methacrylic acid, vinyl sulfonic acid,vinylbenzylsulfonic acid, vinylbenzenesulfonic acid, vinyl acetate,vinylpyridine, styrene, acrylonitrile, methyl acrylonitrile, vinyl alkylether, vinyl chloride, maleic anhydride, N-vinyl-2-pyrrolidone,2-acrylamido-2-methylpropanesulfonic acid, N-vinyl-2-pyrrolidone,N-vinyl formamide, and the like. Particularly preferred polymers includecopolymers of N-vinyl-2-pyrrolidone and acrylamide; terpolymers of2-acrylamido-2-methylpropanesulfonic acid, acrylamide andN-vinyl-2-pyrrolidone; and copolymers ofsodium-2-acrylamido-2-methylpropanesulfonate and acrylamide. Othersuitable gellable polymers contain crosslinkable phosphonate groups, forexample, polymers which incorporate phosphonic acid monomers.Particularly preferred are copolymers of vinyl phosphonic acid monomersand acrylamide, copolymers of vinyl phosphonic acid monomers andmethacrylamide or copolymers of vinyl phosphonic acid monomers,acrylamide and methacrylamide. These copolymers may also incorporate oneor more further comonomers selected from the group consisting of acrylicacid, methacrylic acid, vinyl sulfonic acid, vinylbenzylsulfonic acid,vinylbenzenesulfonic acid, vinyl acetate, vinylpyridine, styrene,acrylonitrile, methyl acrylonitrile, vinyl alkyl ether, vinyl chloride,maleic anhydride, N-vinyl-2-pyrrolidone,2-acrylamido-2-methylpropanesulfonic acid, N-vinyl-2-pyrrolidone,N-vinyl formamide, and the like.

Where the polymer is an acrylamide or related polymer, the mole percentof structural units containing carboxylate and/or phosphonate groups inthe polymer is generally in the range of from 0.01 to 75 mole %. It ispreferred that the mole percent of structural units containingcarboxylate and/or phosphonate groups is in the range of 0.1 to 45,preferably 0.1 to 25, and most preferably 0.1 to 10 mole %.

Generally, the molecular weight of the acrylamide or related polymer isin the range of 10,000 to 50,000,000, preferably in the range 100,000 to20,000,000, more preferably 200,000 to 15,000,000.

Further gellable polymers for use in the present invention include graftcopolymers prepared by reacting hydrophilic polymers with certain allylor vinyl monomers having a crosslinkable substituent. For example, graftcopolymers of hydrophilic polymers and vinyl phosphonate are disclosedin U.S. Pat. No. 5,701,956 which is herein incorporated by reference.The hydrophilic polymer may be selected from polyacrylamides,polymethacrylamides, partially hydrolysed polyacrylamide, partiallyhydrolysed polymethacrylamide, copolymers containing acrylamide,copolymers containing methacrylamide, hydroxyalkylcelluloses, guar gumand derivatives thereof and the like. Graft copolymers of cellulosederivatives are described in U.S. Pat. No. 4,982,793 and U.S. Pat. No.5,067,565 which are herein incorporated by reference. Preferably, thecellulose derivative is a hydroxyalkyl cellulose, in particular,hydroxyethyl cellulose. The preferred grafting monomers include glycerylallyl ether, 2,3-dihydroxypropylmethacrylate, vinyl phosphonic acid,allyl glycidyl ether and glycidyl methacrylate.

The concentration of the gellable polymer in the gelling composition isgenerally in the range of about 0.01 to 0.5 weight percent, preferablyabout 0.05 to 0.4 weight percent, more preferably 0.05 to 0.35 weightpercent, for example, 0.15 to 0.35 weight percent. A relatively lowconcentration of gellable polymer is advantageous since this mitigatesthe risk of a rigid blocking gel being formed in the formation.

Preferably, the gelling composition contains a buffering agent.Preferably, the buffering agent has a buffering capacity at a pH of upto about 5.5, preferably in a pH range of 4.5 to 5.5. A typicalbuffering agent is sodium acetate/acetic acid. Where the gellingcomposition contains a buffering agent, the concentration of bufferingagent will be dependent on the type of buffering agent employed and thebuffering capacity of the rock formation. Generally, it is preferredthat the buffering agent is present at a concentration in the range0.001 to 10% by weight, preferably 0.01 to 1% by weight (based on theweight of the gelling composition).

As discussed above, the aqueous gelling composition may include across-linking agent to further enhance the development of viscosity bycross-linking crosslinkable groups on the gellable the polymer. Thecross-linking agent may comprise any of the well known polyvalent metalcompounds which are capable of creating a cross-linked structure withthe particular polymer utilized. The presently preferred polyvalentmetal compound is a metal compound selected from the group consisting ofzirconium compounds, titanium compounds, aluminum compounds, ironcompounds, chromium compounds, hafnium compounds, niobium compounds andantimony compounds, preferably zirconium and titanium compounds.Examples of suitable multivalent metallic compounds include, but are notlimited to, ammonium zirconium carbonate, sodium zirconium carbonate,potassium zirconium carbonate, ammonium zirconium fluoride, ammoniumzirconium chloride, zirconium ammonium citrate, zirconium chloride,tetrakis(triethanolamine)zirconate, zirconium carbonate, zirconylammonium carbonate, sodium zirconium lactate, zirconium lactate,zirconium acetylacetonate, zirconium diisopropylamine, zirconium2-ethylhexanoate, zirconium acetate, zirconium neodecanoate, zirconiumcomplex of hydroxyethyl glycine, zirconium malonate, zirconiumpropionate, zirconium tartrate, ammonium titanium carbonate, titaniumacetylacetonate, titanium ethylacetoacetate, titanium triethanolamine,ammonium titanium lactate, titanium chloride, titanium carbonate,ammonium titanium chloride, titanium acetylacetonate, titaniumtriethanolamine, chromium citrate, aluminum acetate, potassiumpyroantimonate, and combinations of any two or more thereof. Thesecompounds are commercially available. Preferably, the crosslinking agentis a zirconium lactate of formula [CH₃CH(OH)CO₂]_(n)X_(m)Zr wherein X isan mono-valent anion, for example, a halide (chloride, bromide, iodideor fluoride) or hydroxide, m and n are integers such that m+n=4 and n is1 to 4, preferably 3 or 4.

The concentration of crosslinking agent in the gelling composition mayvary over a broad range of from 0.001 to 0.5 weight percent based on theconcentration of the polyvalent metal. The concentration of crosslinkingagent in the gelling composition is preferably in the range of 0.01 to0.25 weight percent, more preferably 0.025 to 0.2 weight percent, mostpreferably 0.025 to 0.15 weight percent based on the concentration ofthe polyvalent metal.

The aqueous fluid which is used to prepare the gelling composition maybe pure water, tap water, seawater, aquifer water, a synthetic brine ora produced brine.

In a typical treatment, an aqueous pre-flush fluid (for example, a brineor fresh water) may first be injected (from a surface injectionfacility) through a well into the porous formation followed by thegelling composition (injected either as an admixture or sequentially, asdiscussed above) and an optional overflush fluid. Preferably, thegelling composition is introduced into an aqueous zone of the poroussubterranean formation. However, it is also envisaged that the gellingcomposition maybe introduced into a hydrocarbon zone of the poroussubterranean formation. Without wishing to be bound by any theory it isbelieved that the gel which is formed within the pores of the formationacts as a relative permeability modifier. Thus, hydrocarbon formationfluids diffuse or percolate through the gel at a faster rate thanaqueous formation fluids.

The well may then be shut-in for a short period of time of up to 50hours, preferably 2 to 24 hours, for example, 5 to 15 hours before thewell is put back on production. After the well is put back inproduction, the production chemical is controllably released into theformation fluids and into the produced fluids upon degradation of thegel. The produced fluids may be analysed, for example, at the surface tomonitor the concentration of production chemical to determine the needfor further treatments.

The amount of production chemical used is preferably in the range from1-25% w/w of the gelling composition, more preferably from 5-15% w/w,most preferably from 6-10% w/w. Within these ranges the amount usedwould depend upon the nature of the chemical used and its intendedpurpose.

Where the components of the gelling composition are injectedsimultaneously, the gelling composition may contain a gelation delayingagent in order to mitigate the risk of the gel being set up prematurely,for example, in the wellbore. A gelation delaying agent is definedherein as a chemical or mixture of chemicals which delays the rate ofgelation. A delaying agent useful for the retardation of the rate ofgelation is generally a carboxylic acid or salts thereof. A commonlyknown delaying agent can also be an amine that has more than onefunctional group and contains one or more hydroxyls and that can chelatethe polyvalent metal moiety of the polyvalent metal compound. It isenvisaged that the oil field or gas field production chemical, inparticular, a scale inhibitor, may itself act as a gelation delayingagent.

Suitably, the extent of gelation of the polymer is such that the gelwhich is formed within the formation is strong enough to encapsulate anaqueous solution or dispersion of the production chemical and/orparticles comprising the production chemical within its structure.

The gelation rate is generally longer than 1 hour, preferably longerthan 2 hours, more preferably longer than 3 hours, most preferablylonger than 4 hours, for example, longer than 10 hours.

Preferably, the gel which is set up in the formation is capable ofgradually breaking so as to controllably release the solution ordispersion of the production chemical or the particles comprising theproduction chemical into the formation fluid.

The gel may degrade under the conditions encountered in the formation.Thus, the gel may be thermally degradable or biodegradable. The rate ofdegradation of the gel will be dependent upon, amongst othersparameters, the formation temperature, the formation pressure, water cutof the produced fluids, formation permeability, flow rate and depth ofplacement. Suitably the gel starts to thermally degrade at a temperaturein the range 50 to 150° C., preferably 50 to 100° C.

Alternatively, the gelling composition may contain an effective amountof a gel breaker so as to provide controlled breaking of the gel. Thegel breaker may be selected from mild oxidizing agents such as ammoniumpersulfate, potassium dichromate, potassium permanganate, peroxides,alkali metal chlorites and alkali metal hypochlorites. Alternatively,the gel breaker may be a borate. It is also envisaged that theproduction chemical, for example, a scale inhibitor may act as asequestration agent for the polyvalent ion of the crosslinking agentthereby acting as a gel breaker. Where the gellable polymer is apolysaccharide or a cellulose ether derivative, enzymes may be used asbreakers. Suitable enzymes are alpha and beta amylases,amyloglucosidase, oligoglucosidase, invertase, maltase, cellulase andhemicellulase. Acids (for example, peracids) or chelants (for example,ethylenediaminetetracetic acid) may also be used to break the gel.

The amount of breaker employed is that required to reduce the viscosityof the gelled composition to a preselected lower viscosity or to achievea complete break within a desired period of time. The optimum oreffective amount of breaker employed in the present invention depends onfactors such as the desired life of the gel, the particular gellablepolymer and its concentration, the particular breaker and the formationtemperature as well as other factors. Typically, however, from about 0.1to about 10 wt % of breaker is employed in the gelling composition.Preferably, the amount of breaker employed is such to achieve a desiredbreak in from about 12 to 500 hours. It is envisaged that the breakermay be encapsulated in the gelling composition. Alternatively, thebreaker may be contained in the aqueous pre-flush fluid and issubsequently back produced through the gel.

In particular, the present invention provides a method for increasingthe effectiveness of an oil or gas field production chemical by reducingthe number of squeezing and shut-in operations needed to increase theproduction rate from a wellbore penetrating a hydrocarbon-bearing poroussubterranean formation, said method comprising:

-   A) injecting a gelling composition comprising an aqueous liquid, an    oil or gas field production chemical and a gellable polymer through    the wellbore into the porous subterranean formation wherein the    polymer forms a gel in the formation thereby encapsulating the oil    or gas field production chemical in the gel;-   B) after injecting the gelling composition, optionally over-flushing    the porous subterranean formation with an aqueous fluid or an oil;-   C) subsequently, shutting-in the well for a period of time; and-   D) putting the well back on production and controllably releasing    the oil or gas field production chemical from the gel into a    formation fluid that is being produced from the well.

The invention will now be illustrated by means of the followingexamples.

EXAMPLES

Preparation of Gelling Composition

Xanthan gum (BARAXAN D™ ex Baroid), 2.5 g, was weighed into a plasticweighing boat. 497.5 g of filtered seawater (0.45 μm mesh), collectedoff the Dorset coast, was weighed out into a 1 litre beaker. A stirrerpellet (typically 30 mm in length) was placed in the beaker which wasthen placed on a magnetic stirrer. The stirrer was switched on and thestirrer speed increased until a vortex was created in the seawater. Thexanthan gum powder was then gradually introduced into the vortex. Theresulting mixture was stirred until all of the powder had completelydissolved. 50 ml aliquots of this solution were then syringed into 4 ozpowder jars.

2.5m1 of a 20% active solution of scale inhibitor (CALNOX ML3263™,(a 40%by weight solution (pH of 6) of a sodium salt of polyvinyl sulphonatepolvacrylic acid copolymer) ex Baker Petrolite) in seawater was added toeach sample jar. Once the scale inhibitor had been introduced, the lidswere replaced, and the jars were shaken for 30 seconds.

1 ml of a buffer solution was then pipetted into each jar. The jar lidswere replaced and the jars were again shaken for 30 seconds. The bufferformulation employed was prepared by mixing:

1) 20% wt/vol glacial acetic acid in deionised water, and

2) 50% wt/vol sodium acetate trihydrate in deionised water,

at a ratio of 1.262:1.86 vol/vol.

A 7% active solution of sodium zirconium lactate crosslinking agent wasprepared by diluting a 50% active solution supplied by MEL chemicalswith seawater. 1.43 ml of the crosslinking agent solution was added toeach powder jar, and the jars shaken for 30 seconds.

The viscosity of the samples was measured using a Brookfield viscometer(LADV1 having RVT and HAT spindle assemblies) immediately after additionof the crosslinking agent solution. Measurements were also made one hourand 16 hours after addition of the crosslinking agent solution with thesamples maintained at a temperature of 25° C. during aging by means of aJulabo™ water bath. The results of the viscosity measurements are givenin Table 1.

TABLE 1 Viscosity Measurements Viscosity (cP) Time (mins) 30.6 s⁻¹ 61.2s⁻¹ 183.6 s⁻¹  0 52.5 38.4 17.0  60 160.1 101.9 40.3 960 190.9 117.842.1Sandpack Tests

The performance of the gelling composition was assessed using a sandpack test. In this test, a 1 metre metal column of internal diameter1.27 cm was packed with sand (deconsolidated Clashach sandstone, acidwashed and sieved to a 20/40 mesh size) which was then saturated withsimulated formation water. By comparing the dry weight of the columnwith the wet weight, the liquid pore volume of the pack was determined.The pack was then placed in an oven and was connected to a pumpingsystem that allowed fluids to be injected into the pack at a knownvolumetric flow rate with fluid effluent exiting the pack via a backpressure regulator. The back pressure regulator allowed the pack to bepressurised and heated to above the boiling point of water at ambienttemperature. The fluid effluent stream was fed into a sample fractioncollector thereby allowing known volumes of samples to be collected forsubsequent analysis.

Test Procedure

A sandpack of known liquid pore volume (of between 16.5 and 16.9 ml) wasplaced in the oven assembly and heated to a temperature of 120° C. withthe back pressure regulator set to a pressure of 80 barg. When thesandpack had reached the test temperature, 0.25 pore volumes (ca. 10 ml)of treatment fluid was pumped into the sandpack at a rate of 60 ml/hour.The treatment fluid was either a simulated seawater solution of CALNOXML3263™ (ex Baker Petrolite) having the same active content of scaleinhibitor as the gelling composition prepared as described above(control experiment) or the gelling composition prepared as describedabove left to age for one hour following addition of the crosslinkingagent solution (experiment according to the present invention). 0.25pore volumes (ca. 10 ml) of simulated seawater was then pumped into thesandpack at a flow rate of 60 ml/hour. The sandpack was then closed offand maintained at a temperature of 120° C. for 24 hours. After the shutin period, the sandpack was physically turned around in the ovenassembly so that fluids could be injected into the sandpack in thereverse direction to simulate ‘back’ flow of a production well.Simulated seawater was then injected into the sandpack at a flow rate of60 ml/hour for up to 8 hours and either 5 ml or 10 ml samples of thefluid effluent stream were collected for analysis.

The concentration of scale inhibitor (CALNOX ML3263™) in the elutedfluid effluent stream was determined by titrating a known volume ofbarium chloride solution into the samples and measuring the turbiditydeveloped after 3 minutes using a Hach turbidity meter. The turbidityreading was converted to a scale inhibitor concentration by reference toa previously determined calibrations curve. The results of thesesandpack tests were given in Table 2 below.

The composition of the simulated seawater employed in the above testprocedure is as follows:

ion Concentration (ppm) Na⁺ 11010  K⁺ 460 Mg²⁺ 1368  Ca²⁺ 428 Sr²⁺  8Cl⁻ 19700  SO₄ ²⁻ 2960  HCO³⁻ 124

TABLE 2 Sandpack Tests Control Gelling Composition Volume Volume elutedML3263 Concentration eluted ML3263 Concentration (ml) (ppm) (ml) (ppm) 50.00 10 0.00 10 0.00 20 0.00 15 0.00 30 0.00 20 0.00 40 0.00 25 0.00 500.00 30 1.34 60 0.00 35 19.05 70 0.00 40 18.12 80 0.00 45 28.37 90 0.0050 48.87 100 0.00 55 60.05 110 1.34 60 253.59 120 2.28 65 8798.92 1307.87 70 19980.43 140 10.66 75 25571.19 150 28.37 80 28366.57 160 32.0985 38097.28 170 35.82 90 45551.62 180 41.41 95 41824.45 190 346.77 10026502.98 200 859.25 105 21844.02 210 3064.29 110 11853.80 220 7194.84115 2091.22 230 16253.26 120 1998.04 240 18116.85 125 812.66 25018116.85 130 346.77 260 17185.05 135 25.57 270 15321.47 140 19.98 28010662.50 145 18.12 290 4399.46 150 13.46 300 1604.08 155 8.80 3101387.07 160 5.07 320 160.41 165 0.41 330 40.48 340 19.98

The data show that the length of time over which the scale inhibitor iseluted from the pack is increased by the use of the gelling compositionof the present invention.

Field Trial

The performance of the gelling composition was assessed in a field trialundertaken on the Miller field in the North Sea wherein treatment slugs1 to 5 (see Table 3) were sequentially injected into the formation viaan injection line into a production wellbore. Treatment slug 1 wasprepared by spiking the scale inhibitor solution into seawater flowingthrough the injection line. Treatment slug 2 was prepared by adding thespecified amounts of xanthan gum powder, scale inhibitor solution, andbuffer solution to a first batch tank and making up the volume to 95barrels (bbl) with seawater. The resulting mixture was then passed, inseries, through 3 further batch tanks, to allow hydration of the xanthangum, before being injected into the production wellbore. Treatment slug3 was prepared by adding the specified amounts of xanthan gum powder,scale inhibitor solution, and buffer solution to a first batch tank andmaking up the volume to 95 bbl with seawater. The resulting mixture wasthen passed in series through 11 further batch tanks, to allow hydrationof the xanthan gum. The crosslinking agent was spiked into the resultingsolution during injection of the solution into the production wellbore.Treatment slug 4 was prepared by adding the specified amount of xanthangum powder, scale inhibitor solution and buffer solution to a firstbatch tank and making up the volume to 95 bbl with seawater. Theresulting mixture was then passed, in series, through 3 further batchtanks to allow hydration of the xanthan gum, before being injected intothe production wellbore. Treatment slug 5 was prepared by spiking thescale inhibitor solution into seawater flowing through the injectionline. After injection of the treatment slug 5 the well was shut-in for 2hours before putting the well back on production. The data presented inTable 4 show that scale inhibitor is released into the produced waterfrom the gel that is set up in the formation. The data also show thatbarium was not being depleted from the produced water throughprecipitation of barium sulfate therefrom. Furthermore, it was foundthat the treatment had no detrimental effect on the well as evidenced bythe rate of oil production 5 days post treatment being substantially thesame as the pre-treatment production rate.

TABLE 3 Injected Sluge Volume Treatment Stage Slug (bbl) SlugComposition Preflush 1 500 Seawater with: 0.1% by volume of CALNOXML3263 ™ (scale inhibitor solution)¹ Main Treatment 2 380 Seawater with:2% by volume of CALNOX ML3263 ™ (scale inhibitor solution)¹ 0.5% byweight of Xanthan powder² 2% by volume of SCW 85134 (sodiumacetate/acetic acid buffer solution)³ Main Treatment 3 1140  Seawaterwith: 2% by volume of CALNOX ML3263 ™ (scale inhibitor solution)¹ 0.5%by weight of Xanthan powder² 2% by volume of SCW 85134 (sodiumacetate/acetic acid buffer solution)³ 0.5% by volume of SCW 85169(sodium zirconium lactate crosslinking agent solution)⁴ Main Treatment 4380 Seawater with: 2% by volume of CALNOX ML3263 ™ (scale inhibitorsolution)¹ 0.5% by weight of Xanthan powder² 2% by volume of SCW 85134(sodium acetate/acetic acid buffer solution)³ Overflush 5 500 Seawaterwith 0.1% by volume of ML3263 ™ (scale inhibitor solution)¹

-   1. CALNOX ML 3263™ solution as supplied by Baker Petrolite from a    first and a second “tote” tank wherein the volume of solution in the    first and second tanks was 4546 and 2272 litres respectively.-   2. Xanthan supplied in 61×25 kg sacks.-   3. SCW 85134 buffer solution as supplied by Baker Petrolite from a    first and a second “tote tank” wherein the volume of solution in the    first and second tanks was 4546 and 2272 litres respectively.-   4. SCW 85169 crosslinking agent solution as supplied by Baker    Petrolite in 205 litre drums (4.5 drums required for treatment slug    3).

TABLE 4 Flow Back Data Scale Inhibitor Cumulative Ba (mg/l) in (ppm) in% Scale Cumulative Produced Produced Produced Inhibitor Produced OilWater (bbls) Water Water returned. (bbls)  2,183 410 30281  21.0  2,159 2,750 115 44171  28.9  2,720  3,274  81 54935  38.0  3,238  4,278 1165296  39.7  4,231  5,369  81 2872  40.7  5,310  6,548 113 1073  41.1 6,476  9,123 136 458 41.5  9,023 13,662 161 411 42.1 13,512 13,881 175292 42.1 13,728 16,762 172 323 42.4 16,577 21,477 169 158 42.6 21,24022,176 195 187 42.7 21,930 35,495 178 113 43.2 35,097 40,037 155  5443.2 39,587 53,312 166  50 43.4 52,711 57,854 153  43 43.5 57,200

1. A method of introducing an oil field or gas field production chemicalinto a hydrocarbon-bearing porous subterranean formation penetrated by awellbore comprising: injecting a gelling composition comprising anaqueous liquid, an oil field or gas field production chemical, and agellable polymer through the wellbore into the porous subterraneanformation wherein the gellable polymer forms a gel within the pores ofthe subterranean formation thereby encapsulating the production chemicalin the gel; and controllably releasing the production chemical from thegel into a formation fluid.
 2. A method as claimed in claim 1 whereinthe gelling composition comprises (i) an aqueous liquid, (ii) an oil orgas field production chemical, (iii) a gellable polymer havingcrosslinkable groups, and (iv) a crosslinking agent and wherein the gelis formed within the pores of formation through crosslinking of thecrosslinkable groups of the gellable polymer with the crosslinkingagent.
 3. A method as claimed in claim 2 wherein the cross-linking agentis a polyvalent metal compound selected from the group consisting ofpolyvalent compounds of zirconium titanium, aluminum, iron, chromium,hafnium, niobium and antimony.
 4. A method as claimed in claim 3 whereinthe concentration of crosslinking agent in the gelling composition isfrom 0.001 to 0.5 weight percent based on the concentration of thepolyvalent metal.
 5. A method as claimed in claim 1 wherein theproduction chemical is controllably released from the gel into theformation fluid in the near wellbore region of the formation.
 6. Amethod as claimed in claim 1 wherein the formation fluid is selectedfrom the group consisting of a formation brine, crude oil, natural gasand gas field condensate.
 7. A method as claimed in claim 1 wherein theoil or gas field production chemical is selected from the groupconsisting of (i) scale inhibitors, (ii) corrosion inhibitors, (iii)hydrogen sulphide scavengers and (iv) hydrate inhibitors.
 8. A method asclaimed in claim 1 wherein the production chemical is suspended in theaqueous liquid in the form of particles having a particle size of 100%less than 10 microns.
 9. A method as claimed in claim 8 wherein theparticles of production chemical are coated with a coating agentselected from water-soluble polymers and oil-soluble polymers.
 10. Amethod as claimed in claim 1 wherein the gellable polymer is selectedfrom the group consisting of biopolysaccharides, cellulose ethers andacrylamide-containing polymers.
 11. A method as claimed in claim 1wherein the concentration of the gellable polymer in the gellingcomposition is in the range of about 0.01 to 0.5 weight percent.
 12. Amethod as claimed in claim 1 wherein the gelling compositionadditionally comprises a buffering agent having a buffering capacity ata pH of up to about 5.5.
 13. A method as claimed in claim 12 wherein thebuffering agent is present in the gelling composition at a concentrationin the range 0.001 to 10% by weight based on the weight of the gellingcomposition.
 14. A method as claimed in claim 1 wherein the amount ofproduction chemical is the gelling composition is in the range from1-25% by weight.
 15. A method as claimed in claim 1 wherein theproduction chemical is released into the formation fluid through thermaland/or biodegradation of the gel under the conditions encountered in theformation.
 16. A method as claimed in claim 15 wherein the gel starts tothermally degrade at a temperature in the range 50 to 150° C.
 17. Amethod as claimed in claim 1 wherein the gelling composition contains aneffective amount of a gel breaker so as to provide controlled breakingof the gel.
 18. A method as claimed in claim 17 wherein the gellingcomposition comprises from 0.1 to about 10 wt % of gel breaker.
 19. Amethod of increasing the effectiveness of an oil or gas field productionchemical by reducing the number of squeezing and shut-in operationsneeded to increase the production rate from a wellbore penetrating ahydrocarbon-bearing porous subterranean formation, said methodcomprising: A) injecting a gelling composition comprising an aqueousliquid, an oil or gas field production chemical and a gellable polymerthrough the wellbore into the porous subterranean formation wherein thepolymer forms a gel in the formation thereby encapsulating the oil orgas field production chemical in the gel; B) after injecting the gellingcomposition, optionally over-flushing the porous subterranean formationwith an aqueous fluid or an oil; C) subsequently, shutting-in the wellfor a period of time; and D) putting the well back on production andcontrollably releasing the oil or gas field production chemical from thegel into a formation fluid that is being produced from the well.
 20. Amethod as claimed in claim 19 wherein the well is shut-in for a periodof up to 50 hours before putting the well back on production.
 21. Amethod of introducing an oil field or gas field production chemical intoa hydrocarbon-bearing porous subterranean formation penetrated by awellbore comprising: forming a polymer slug by dispersing or dissolvinga gellable polymer in a first aqueous fluid; forming a crosslinkingagent slug by dissolving a crosslinking agent in a second aqueous fluid;dispersing, suspending or dissolving a production chemical in thepolymer slug and/or the crosslinking agent slug; forming a gellingcomposition within the pores of the formation by either: (a) injectingthe polymer slug into the porous subterranean formation prior toinjecting the crosslinking agent slug and back-producing the polymerslug over the crosslinking agent slug or (b) injecting the crosslinkingagent slug into the porous subterranean formation prior to injecting thepolymer slug and back-producing the crosslinking agent slug over thepolymer slug.
 22. A method as claimed in claim 21 wherein an aqueousspacer is injected between the polymer slug and crosslinking agent slugand optionally an aqueous pre-flush fluid is injected into the poroussubterranean formation prior to injection of the polymer slug,crosslinking slug and aqueous spacer.
 23. A method as claimed in claim21 wherein the production chemical is dissolved, dispersed or suspendedin one or more of the aqueous pre-flush fluid, the polymer slug, thecrosslinking agent slug or aqueous spacer.